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Cabot Oil & Gas (NYSE:COG)

Q3 2010 Earnings Call

October 26, 2010 9:30 am ET

Executives

Dan Dinges – Chairman, President, Chief Executive Officer

Scott Schroeder – Vice President, Chief Financial Officer

Phil Stalnaker – Vice President, Regional Manager - North Region

Matt Reid – Vice President, Regional Manager – South Region

Analysts

Brian Lively – Tudor, Pickering, Holt & Co.

Brian Singer – Goldman Sachs & Co.

Michael Hall – Wells Fargo Securities

Gil Yang – Bank of America/Merrill Lynch

Raymond Deacon – Pritchard Capital Partners

Biju Perincheril – Jefferies & Co.

Robert Christensen – Buckingham Research Group

Marshall Carver – Capital One Southcoast

Jack Aydin – Keybanc Capital Markets

Operator

Good morning ladies and gentlemen. My name is Christy and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas Third Quarter 2010 Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key.

I would now like to hand the program over to Mr. Dan Dinges, Chairman, President and CEO. Please go ahead, sir.

Dan Dinges

Thanks Christy and good morning. Appreciate you joining us for this third quarter teleconference call. I have Scott Schroeder, our CFO; Jeff Hutton, VP of Marketing; Matt Reid, VP of our South Region; and Phil Stalnaker, VP of our North Region joining me today for the call.

Before we start, forward-looking statements included in the press release apply to my comments today.

Now let’s get into our releases last night for the quarter. Cabot Oil & Gas reported clean net income of approximately $32 million or $0.31 per share, which exceeded consensus expectations. When you compare these numbers against the previous year third quarter, lower natural gas prices, even with our higher production, did not match the previous year numbers. The selected items for the quarter were mainly an impairment and pension termination-related expenses. The impairment includes two legacy South Texas fields that have not received any capital and we have no planned operations for 2011. The pension charge relates to the acceleration of costs for the plan which the Company terminated September 30, 2010. This amortization will occur for the next five quarters as we go through the regulatory process to unwind the plan.

A highlight of the quarter and, I think, a very positive trend was 41% production growth versus last year’s comparable production volumes for the third quarter. Sequentially from the second quarter, production grew 18%, another significant accomplishment as the Company exceeded its production guidance targets. Additionally year-to-date growth levels are 22% over last year’s first nine months; and in fact yesterday our year-to-date production matched the full year level reported for 2009, so our production for the remainder of the year will represent year-over-year growth.

Natural gas prices, everybody’s aware, very soft. The realization’s experienced a 27% decline for the quarter while oil prices remain strong. Both realizations were positively impacted by hedges for the quarter.

In terms of hedging, we remain relatively unhedged for 2011 but we did add a costless collar contract for all of 2011, which is indicated on our website.

In our guidance – we did post new guidance increasing fourth quarter production for 2010 and established 2009 guidance. The full year expectation for 2010 is now about 25% reported growth. As we move into 2011 and with the second phase of Lathrop still pending, we are providing volumes for the first quarter of 2011 only. However, with no additional capacity from Lathrop, growth expectations are approximately 20% for 2011 full year, and depending on the ultimate timing with Lathrop, percentage growth would only increase from that floor. As soon as we have full clarity on this point, we will communicate the timing and fine-tune further growth expectations.

The new guidance for costs highlights the impact of the expanding production base combined with operations focused in just three basins for 2011. Additionally, the capital program changes are identified, establishing 2011 at 600 million and moving the remainder of 2010 up 65 million to 790 million. The two main reasons for the capital increase are our participation in non-operated wells in the Haynesville/Bossier combined with the increased cost of pumping services the industry is seeing across the board.

To assist with capital allocation in 2011 in the Haynesville/Bossier area, we are working on a joint venture to fund this area for 2011. Additionally we have provided for an increase to our estimates for pumping services commensurate with current levels, plus added a factor for inflation. Also, we will reduce our rig activity in both regions next year; however, we will still be able to realize our production growth projections established in our guidance.

Now let’s move to operations. While we currently have operations ongoing in the Marcellus, Haynesville and Eagle Ford for 2011, we will concentrate our capital allocation in the Marcellus and Eagle Ford. In the South Region for the remainder of 2010, Cabot is participating in 16 outside operated Haynesville/Bossier wells that are currently drilling, completing, or waiting on completion with working interests generally ranging from 10 to 20%. Results today in the play continue to show production at high initial rates with excellent recoverable reserves. This is true for both the Haynesville and Bossier formations, so we continue to be encouraged by the Bossier wells on and around our acreage.

Cabot has participated in four Bossier wells in this area. Two of the wells have been completed and have performed equal to or better than the Haynesville completions. The other two remaining wells are scheduled to be completed before year-end. This recent success reinforces our belief that our acreage is located in a core area for both zones. Though unpopular today, our capital allocated this play continues to capture a significant resource potential for the future.

As I previously mentioned, Cabot is seeking a 33% working interest in non-operated—non-operating partner in our Haynesville/Bossier acreage. This joint venture would potentially include some upfront consideration plus a capital carry and an AMI which allows for participation in future acreage acquisition. This process is moving forward as we speak.

Moving down further South Texas, as reported last night, the Company successfully completed its third Eagle Ford well, the Arminius Energy Trust #2H, which is a 100% operated Cabot well. Located in Frio County, it was drilled to a total depth of 13,175 with a 4,325 foot lateral and is cleaning up, and hit a peak rate of over 600 barrels equivalent yesterday. This well is located in our Buckhorn area. The fourth Company-operated well, the Cromwell Ranch 1H, another 100% Cabot well located in La Salle County, was drilled with a lateral length of 6,000 feet and is scheduled for completion in the next couple of weeks. Additionally, additional drilling in the prospect area is scheduled for later this quarter. Cabot holds approximately 53,000 net acres in the oil window of the play and has over 300 net potential locations.

Also in the Eagle Ford oil trend, drilling on our 18,000 acre area of mutual interest with EOG is scheduled to begin by year-end. Each company, as you might be aware, contributed 50% of the acreage in the JV with the operator EOG. The current plan is to keep at least one rig active in the JV area throughout 2011. With our South Region capital being allocated between our operated Buckhorn area and the EOG JV, we anticipate potentially doubling our oil volumes in 2011 from 2010.

Now let’s move up to the North Region. In the Marcellus we achieved a new production high of 245 million cubic foot gross per day, predominantly from 43 horizontal wells, and had an outstanding quarter with production growth for the third quarter increasing approximately 74% over the second quarter of 2010. During the quarter, Cabot had two wells exceed the 20 million a day rate for a 24-hour initial production period. One well had a lateral of 4,659 feet in 18 stages while the other had a lateral of 3,960 feet with 15 stages.

Also during the quarter, Cabot completed a three well pad with a total of 55 frac stages, and the three wells are producing a combined 47 million cubic foot, which was highlighted also in the press release last night. Cabot continues to run seven fit for purpose rigs in the Marcellus. Today we have a total of 44 stages currently being completed, 93 stages waiting on pipelines, and 336 stages waiting on completion. With the prolific nature of the wells and completions that we are drilling, coupled with balancing our capital allocation, we will be adjusting our rig count in 2011 to five rigs. Right now we are planning 54 horizontal wells in Susquehanna in 2011 which will provide for a significant growth profile.

On a seismic front, Cabot has completed shooting 250 square miles of 3D seismic data and has participated in the acquisition of an additional 85 square miles of 3D seismic in Susquehanna. Right now, we have all of the 335 miles of 3D data in house being interpreted, which covers approximately 60% of our acreage position in the Marcellus. As many of you are aware, at our Lathrop compression station Cabot is still waiting on the air quality permit for our three additional compressors, which was discussed last quarter. Cabot continues to have discussions with the Pennsylvania DEP to resolve this issue.

On a positive note, we believe with further engineering we can tweak Lathrop Phase 1 to add 10 to 20 million cubic foot more per day. Additionally, we are working towards the development of three additional compressor sites, two of which will be in limited operation during the latter part of 2011. Our expectation is, at a minimum, we will be able to free flow gas through both of these new compressor sites. None of these potential upsides are in our 20% gross sales forecast for 2011.

Our Marcellus is quite a remarkable resource, and even with lower natural gas prices and gas being out of favor with investors, our economic returns are in the top quartile of the food chain. Case in point, while we have seen many strong wells, particularly most recently, our EUR guidance is still only 5.5 Bcf. At the current EUR, 5.5 Bcf, and current pricing, our rate of return will compete with most oil and wet gas projects very favorably. We will update our EUR for Marcellus after our year-end reserve bookings.

Also, Cabot continues to evaluate, along with expert consultants, a nine-square mile area in Susquehanna where the Pennsylvania DEP suspended drilling and fracking operations almost a year ago. Cabot had compiled records of the existence of methane in and around the Dimock area long before Cabot began drilling for natural gas. Additionally, Cabot provided copies of sworn affidavits from residents along Carter Road and other areas who acknowledged they had always had methane in their water and even ignited their water prior to Cabot drilling in their community. Cabot has demonstrated it can remediate the preexisting methane in the water wells by installing methane separations systems. In a technical meeting between the Pennsylvania DEP and Cabot just three days prior to the DEP’s announced pipeline plan, the DEP acknowledged to Cabot that methane separators have worked in other areas in the state and will work in Dimock. This proven technology is a quicker, cost effective, permanent solution to treat the preexisting methane condition. The Cabot offensive has been required to offset the sudden change in the direction of the preferred solution by the Pennsylvania DEP.

Now let’s move back to operations. In the Rocky Mountains in the North Region, our initial rank wildcat in Nevada was dry but it did provide us information to carry to our other two areas in Nevada. It did not condemn our original prospect concept; we just encountered the section a little bit shallower than anticipated. We do plan on shooting additional seismic and continuing our evaluation out there.

In regards to our Montana Heath play, we should be moving a rig in, in the next week or so.

As we continue to execute our program in both regions and look ahead to 2011, we are very well positioned to weather this commodity cycle while still economically building the Company. We have a focus on the Marcellus and Eagle Ford for 2011 with a program that is geared towards cash flow expectations. We are fully aware of concerns of over-extending cash flows in this market—in this type of market, and we will manage these concerns. Additionally, even in this soft natural gas pricing environment, the vast majority of our capital scheduled to be allocated towards the Marcellus and Eagle Ford will deliver very good rate of returns for our shareholders.

Christy, with that we’ll be more than happy to take any questions.

Question and Answer Session

Operator

As a reminder, if you would like to ask a question, please press star, one on your telephone keypad. We will pause for just a moment to compile the roster. Once again, please press star, one to ask a question.

Your first question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Brian Lively – Tudor, Pickering, Holt & Co.

Good morning, Dan.

Dan Dinges

Hey Brian. How are you?

Brian Lively – Tudor, Pickering, Holt & Co.

Doing all right. In the 2011 $600 million CAPEX budget, can you split that between what you’re going to spend in the Marcellus versus the other areas?

Dan Dinges

Yeah, we’re going to spend $350 million in the Marcellus and $250 million in the South Region.

Brian Lively – Tudor, Pickering, Holt & Co.

And within that $350 million Marcellus number, I think you were saying that you could see around 30 wells uncompleted at the end of this year, so I’m sure that would carry over into next year. Is that the right way to think of the budget?

Dan Dinges

Yeah, it’s the right way to think of the budget; but also with our 54 wells scheduled in 2011, as we get to some of those wells at the end of 2011 there will be some carryover into 2012 also.

Brian Lively – Tudor, Pickering, Holt & Co.

Right. And then thinking about the Lathrop Phase 2 compression and how that could limit production next year, can you just discuss how much gas you’ll be able to free flow if you’re not able to get the compression online?

Dan Dinges

Well, we’re going to be looking at the compressor station to the east of the Lathrop Teal stations, and we’re also going to be looking at free flowing gas in a compressor station to the north of our area. And I don’t know exactly and have not seen from the region exactly the timing of the well completions in and around those particular compressor sites, but as a, I guess, a bowie to go by, Brian, that these wells certainly come on at rates that will buck the anticipated line pressure at those particular sites. And our initial rates that we’re seeing out there, particularly with the additional lateral links and frac stages, are typically greater than 10 million a day.

Brian Lively – Tudor, Pickering, Holt & Co.

But do you need that Lathrop Phase 2 compression, then, if the rates are—and the pressures on the wells are above the pipeline pressure to start with?

Dan Dinges

Sure. You know, we’ve been producing now out there wells—in fact, of our 43 horizontal wells, we have a couple of wells that have produced well over a year – almost a year and a half, and those particular wells still flowing at good rates are not over 1,000 pounds flow tubing pressure today, so those are the type of wells that you would like to have compression on.

Brian Lively – Tudor, Pickering, Holt & Co.

Okay, that’s helpful. And then last question, if you’re able to get the permit, how many additional completions do you think you’ll take in the Marcellus next year?

Dan Dinges

I’m not following exactly what you’re asking.

Brian Lively – Tudor, Pickering, Holt & Co.

So the plan is 54 wells—or sorry, yeah, 54 wells next year. If you get the permit in place, how many additional completions do you think you’ll take in the Marcellus with that extra capacity?

Dan Dinges

Well, we have—the Lathrop station, we think could add and additionally up to about 100—between 105 and 120 million cubic foot a day. And when you look at the prolific nature of these wells—for example, just three wells we completed on the Greenwood site are producing over 45 million cubic foot per day just from three wells. So within the 54 wells that we have scheduled for 2011 and the carry-over completions that we see from 2010 with this program, we think we will be able to utilize all of the additional Lathrop compressors and also maybe free flow some gas into those additional compressor sites.

Brian Lively – Tudor, Pickering, Holt & Co.

Thank you.

Dan Dinges

Thank you.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs & Co.

Thanks. Good morning.

Dan Dinges

Hey Brian.

Brian Singer – Goldman Sachs & Co.

On the three wells that you announced from the zipper fracs, can you talk about what you think the EURs are and how indicative you think those can be relative to future wells you plan to drill in Susquehanna?

Dan Dinges

Well, the—it’s early term, obviously, on the production curve and we have seen with our—again, our extended laterals and additional fracs, Brian, we have seen some very, very good rates and the wells holding up very well. We are working and starting our push towards year-end reserves. We do 100% reserve audit, as you might be aware. We are pushing towards doing that and what we’re going to do is after we get our reserve audits, we have a production history from some of these longer laterals, more fracs, at the year-end. We’re going to relook at our EUR, the 5.5, and I think we’ll be adjusting that. But to where we’d be adjusting it right now, Brian, I think it’d be premature.

Brian Singer – Goldman Sachs & Co.

Got it. Thanks. And I guess when you think about moving more towards pads, and I assume based on these results – and correct me if I’m wrong – you would probably look to do more of—use more of the zipper frac technology. What are you seeing in terms of how long it would take to drill the well, complete the well, tie the well into sales?

Dan Dinges

You know, it’s going to depend on—we’re doing a six well pad site right now, and we’re drilling on the sixth well on that pad site; so we have had a rig there—let me visit with Phil one second. How long have we had a rig on that pad?

Phil Stalnaker

Roughly five months.

Dan Dinges

Okay. So we’ve been on that pad site right at five months. We’re finishing up the sixth well right now. We’ll move a crew on there and I would bet that crew will be there a month or more, fracking that pad site.

Brian Singer – Goldman Sachs & Co.

Great.

Dan Dinges

Because on the—one of the things we’re doing is we’re keeping pressure when we’re completing these on the offsets. We’re moving in between the wells to be able to maintain pressure as we frac the offset wells. So it takes a little bit more time just to move up and hook up to the other wells, but that’s probably the timing on that particular pad site.

Brian Singer – Goldman Sachs & Co.

Great, thanks. And then lastly—and I apologize if you mentioned this in your opening comments, but I think you did mention you had built in some cost inflation into the 600 million for next year. Could you be a bit more—provide a little bit more color on where versus today’s costs you are assuming we trend next year that’s built into that 600 million?

Dan Dinges

Yeah, we put in from—so what we’re seeing on the current frac pumping services per stage cost, and the recent bids we received, we’ve used those in our capital program estimates; and we put a 5 to 10%, depending on the area and the service, into our capital program.

Brian Singer – Goldman Sachs & Co.

Great. Thank you.

Dan Dinges

Thank you.

Operator

Your next question comes from the line of Michael Hall with Wells Fargo.

Michael Hall – Wells Fargo Securities

Thanks. Good morning everyone.

Dan Dinges

Good morning, Michael.

Michael Hall – Wells Fargo Securities

Just a little more on the $600 million spending outlook for next year. Is there any land associated or assumed within that level?

Dan Dinges

Yes. We have $25 million in the program.

Michael Hall – Wells Fargo Securities

And is that just predominantly infill (inaudible) in the Marcellus, or is that—

Dan Dinges

Yeah. Just—it’s consolidating positions in the Marcellus as we continue to do that up there; and it’s also to pick up any additional acreage in any well units that we have scheduled.

Michael Hall – Wells Fargo Securities

Okay. And then on the—in the south, the Eagle Ford spending level—I mean, is it—call it like 125 million, I mean, about half of that 250 million? Or is it—how should I think about that?

Dan Dinges

Probably it’s a little bit more than half of that. It’s a little bit more than you’d mentioned.

Michael Hall – Wells Fargo Securities

Okay. And so what kind of type curve are you assuming in the Eagle Ford currently on that doubling liquid volumes with—for next year?

Dan Dinges

I’m sorry – you broke up just a little bit on me.

Michael Hall – Wells Fargo Securities

What sort of type curve are you assuming for the Eagle Ford program next year in your commentary that you’re going to double liquid to volume?

Dan Dinges

Well, we’re kind of looking at the Arminius wells that we’ve just drilled, and we used those wells, that—the initial rates. And right now we’re still obtaining the decline curve but we’re using what kind of industry has right around in that area for that decline curve.

Michael Hall – Wells Fargo Securities

Okay, fair enough. And then lastly, if you think about getting Lathrop—let’s say we assume it’s on for the second half, you know, Phase 2. What does the completion backlog look like as you exit 2011? Have you looked at that?

Dan Dinges

Well, we have—we have some wells that we already have completed, and I mentioned that we have a number of wells that we’re currently completing. We have, like, 44 stages we’re currently completing. We have eight wells with 93 stages that are waiting on a pipeline, and those—and again, the wells that we’re currently completing. So we have a pretty good lineup to flow into Lathrop once we can get that air quality permit.

Michael Hall – Wells Fargo Securities

Okay. I guess one more, then. On the timing and on the air quality permit, any—obviously (inaudible) give us the expected timing currently, but any thoughts on when you might have additional clarity on that? When are you hoping for having some better certainty around that?

Dan Dinges

Yeah we have, again, submitted the information to the DEP. The DEP has had it. The regulatory process in Pennsylvania right now is, I think at best, unpredictable for us at this stage; and we continue, though, to communicate and make every effort to answer any questions or information that they request of Cabot. We also are continuing to make requests to have meetings with the DEP and to make sure we can facilitate and answer any questions that they may have. So speculating on the timing is difficult. We do know that they had issued recently a permit and that permit was a permit that was simply situated as Cabot’s Lathrop station. So we’re confident that the process used to award that permit would be available to Cabot also.

Michael Hall – Wells Fargo Securities

Okay. Very good. Well, thanks very much.

Dan Dinges

Thank you, Michael.

Operator

Your next question comes from the line of Gil Yang with Bank of America/Merrill Lynch.

Gil Yang – Bank of America/Merrill Lynch

Good morning. The—it sounds like your capital budget for 2011 would be unaffected by when—or the timing of the Lathrop permit issuance. Is that correct?

Dan Dinges

Yes.

Gil Yang – Bank of America/Merrill Lynch

Okay, so we would really—you know, the only difference to us in some sense would be that the exit number of wells that you had awaiting on pipeline would be different, but you wouldn’t spend more or less money if—once the permit is issued, right?

Dan Dinges

That’s correct. We have—we have our budget set, plan on five rigs in the Marcellus. We do anticipate Lathrop to—three compressors to be installed at Lathrop. We’ve only given guidance for first quarter, though, at this stage. But again, with the prolific nature of the well that we see up there, we think the 54 wells and the completions that we have scheduled during 20—actually between now and through 2011, that we will be able to increase our production up there significantly with those wells.

Gil Yang – Bank of America/Merrill Lynch

Could you give us maybe two scenarios – if Lathrop came on January 1 or didn’t, how many wells would you exit the year waiting on pipeline; and how about if Lathrop didn’t come online, how many wells would be waiting on pipeline at the end of the year?

Dan Dinges

You talking about at the end of 2011?

Gil Yang – Bank of America/Merrill Lynch

Right.

Dan Dinges

Or are you talking about the end of 2010?

Gil Yang – Bank of America-Merrill Lynch

No, no. So if in one case, if Lathrop came on—was on for the full year, and in the other case it was not on at all, what would be the exit rate—exit number of waiting on pipeline wells in either case?

Dan Dinges

Well, we have—again, not only do we have the planned three compressors at Lathrop that we—we are looking forward to installing and producing into, we are also moving forward with the additional compressor sites and we are moving forward to set compression there also; but we will free flow gas through those compressor sites, and how many wells we are able to free flow through that, we are still in the planning stages of the total number that would be able to—and would like to drill in and around those particular compressor sites versus in other areas. So that is still a work in progress, to look that far out, Gil. So I don’t have the exact number of how many we would exit in 2011.

Gil Yang – Bank of America/Merrill Lynch

Okay. And these new compressor locations – what kind of permitting issues are required there?

Dan Dinges

We’ll still be submitting the similar-type permits. I think one of the things that I have read out there is in light of an election that’s coming up November 2, I have read that the—both candidates out there have a desire to define the regulatory process in a clear manner and to allow science and technology and clarity to rule as they make decisions. So I look forward to the Pennsylvania DEP able to communicate to industry in a way that would add clarity and allow me to be able to answer the questions that I always get.

Gil Yang – Bank of America/Merrill Lynch

Okay. Does—is there any chance that the Lathrop permits come after these other permits, or do you think that they’ll come in one big lump or, you know, will they be done sort of in the order in which they were filed?

Dan Dinges

No, I think Lathrop would come before the other permit sites.

Gil Yang – Bank of America/Merrill Lynch

Okay. And then last question – the Eagle Ford, you know, the one—I guess your first well was flowing flat for six weeks. Is that on pump? When did it go on pump, and how long do you think it would stay flat? And then, you know, what’s the EUR implication of that?

Dan Dinges

We certainly expected that it would decline. We certainly expect that. I’ll let Matt make a comment on it.

Matt Reid

No, it’s actually—we’ve got actually tubing run on that well and it’ll be flowing for a while. I would anticipate for a couple of months. We’ve got gas lift valves running in it as well. Liquid on gas lift initially and then put it on pump after that.

Gil Yang – Bank of America/Merrill Lynch

Okay. Do you have an EUR expectation for the well?

Matt Reid

We’ve got some typical curves in the area. I would say we’re somewhere between 250 and 300,000 barrels.

Gil Yang – Bank of America/Merrill Lynch

Okay. And what would be the rate of return on that well? What was the cost and what would be the rate of return?

Matt Reid

The cost on the initial well—of course, we moved a rig out of East Texas up—a typical well in there is going to be about 7.5 to 8.5 million. Rate of return is about 40% detax.

Gil Yang – Bank of America/Merrill Lynch

Okay. Okay, thank you very much.

Operator

Your next question comes from the line of Ray Deacon with Pritchard Capital.

Raymond Deacon – Pritchard Capital Partners

Yeah, hey Dan. I was wondering in the 250 million you’re going to spend in 2011, how does the mix shift between Haynesville and Petit? I guess, is there more activity on the Petit in there if you got all the leases held that you—or when do you get the leases held?

Dan Dinges

We do not have a—we do not have Petit drilling in that number, Ray. We’re going to be, again, mainly focused down in the Eagle Ford.

Raymond Deacon – Pritchard Capital Partners

Okay, got it. Got it. And just one other question – with fracking in the Marcellus, I guess, do you feel the need to lock up a frac crew on a long-term basis, and how many of these 11 locations do you have kind of firm dates lined up?

Dan Dinges

Yeah, we are at, right now, Ray, bidding frac crews and trying to establish a longer term relation on our program out there in the Eagle Ford. So yeah, we are out there the market, and we would be—excuse me, in the Marcellus. We are out there trying to establish a term relationship.

Raymond Deacon – Pritchard Capital Partners

Okay, got it. Thanks very much.

Dan Dinges

All right. Thank you, Ray.

Operator

Your next question comes from Biju Perincheril with Jefferies.

Biju Perincheril – Jefferies & Co.

Hey, good morning. A couple of questions – first on the CAPEX, can you give us sort of how much you spent this year and what you plan to spend next year for midstream and leasing?

Dan Dinges

Yeah, we’ve spent about $125 million on leasing this year, and Scott--?

Scott Schroeder

Fifty-eight on pipeline.

Dan Dinges

Fifty-eight million on the—

Scott Schroeder

Pipeline gathering.

Dan Dinges

Pipeline gathering.

Scott Schroeder

Next year it’s 20 and 27.

Dan Dinges

And next year it’s 20 and 27.

Biju Perincheril – Jefferies & Co.

20 and 27. Okay. And then if Lathrop comes on, let’s say, around mid-year or so, what would be the additional CAPEX that you would need to tie in those wells? And similarly for those—you mentioned that you are working on three other pipeline taps and there’s nothing in the volume guidance for those; but is there anything there in the CAPEX number, and if not, what could be the incremental there?

Dan Dinges

Yeah, the—in our number for facilities is the tie in for the Lathrop compressors. We have included, and we include in the cost of our completions, about $150,000 per well that is a—kind of a capture amount for our pipelines and hookups from the well pad to the compressor site. All of that is ongoing right now. In fact, we have all—the majority of that in place already. So any incremental capital, it’s not necessary.

Biju Perincheril – Jefferies & Co.

Okay, so if Lathrop comes on and you had these prolific wells, or you’re—you know, you might be hooking up a few more wells, but you’re saying about 150,000 per well is what will be needed to hook up those wells?

Dan Dinges

Yes, but we already have some of those wells hooked up.

Biju Perincheril – Jefferies & Co.

Got you.

Dan Dinges

They’re ready to go; it’s just a matter of hooking up the compressor site.

Biju Perincheril – Jefferies & Co.

Okay. And—okay. And then other compressor—all the other pipeline taps, those are also in the CAPEX numbers?

Dan Dinges

That’s correct.

Biju Perincheril – Jefferies & Co.

Okay. And then I know you just mentioned—you know, you’re looking at maybe some dedicated crews for Marcellus, but given what we’re seeing in the Eagle Ford area, how are you thinking about that program, especially for next year? You were counting on a pretty significant volume ramp up from there?

Dan Dinges

Yeah, and we are also bidding crews right now for the Eagle Ford.

Biju Perincheril – Jefferies & Co.

Okay, and how many rigs are you going to run there next year? I mean, are you looking at a program that would necessitate a dedicated crew for the year?

Dan Dinges

We would hope to have a couple of rigs running down there the entire year.

Biju Perincheril – Jefferies & Co.

Got it. Okay, thanks for the time. That’s all I had.

Dan Dinges

Thank you, Biju.

Operator

Your next question comes from the line of Robert Christensen with Buckingham Research.

Robert Christensen – Buckingham Research Group

Yes. In East Texas, I gather that there are a number of wells that have been drilled case but not completed, waiting on frac crews. What would you estimate that potential volume—associated volume is that didn’t show up, I guess, in your quarter?

Dan Dinges

We have a number of wells, Robert, that are either waiting on pipeline hookup or waiting on completions. Have probably pushing 10 wells that are waiting on completion, and we have in those wells a varying amount of working interest ownership, so I don’t have that exact—that exact net production number, but a number of them are waiting on completion.

Robert Christensen – Buckingham Research Group

On completion of that. The second thing on this Lathrop station, I mean, what is the exact issue? It sounds like you had to go back and resubmit information. What is—is it Knox or what unusual issue exists with this particular compressor station?

Dan Dinges

Well, the original application was submitted as a single-source point for emissions; in other words, the calculation be done at Lathrop station. And that was pursuant to regulations and the requirement. Somewhere in approximately May timeframe, the DEP indicated that the determination of issuing air quality permits will be based on an aggregation calculation, and that means to aggregate not only the Lathrop emissions but also aggregate it with the Teal compressor site also. And in an aggregation sense, there has not been any clarity on that particular process; and in fact, we’re uncertain on whether or not does aggregation mean that every well that is hooked up to the pipelines and the compressor stations, does that have to be included and does future wells that would be hooked up to that pipeline have to be included? We’re uncertain about all that, and there hasn’t been clear definition provided to industry to answer that question. So the—boiling it down, bottom line is are they making decision as the regulations had provided for on a single-source air quality permit, or are they going to consider aggregation as their requirements to issue air quality permits. That’s the defining question.

Robert Christensen – Buckingham Research Group

Fair. Just coming to the Eagle Ford, would you think your acreage – your 53,000 net acres – is—if we looked across it, do you think the rock qualities could be better away from the current wells you drill? Should we have expectations for better performance off better rock? That’s question one. And question two, what are the early indications of the rock quality over on the JV acreage with EOG, relative to what you’re shown us you’re capable of today?

Dan Dinges

Well, we have—certainly anticipate the differences in the kind of the three areas that we have acreage. The offset wells to EOG’s—to the EOG JV just to the east of us, I think some of those wells are outputting over 1,000 barrels a day with also associated gas. And the area that we have and what we’re producing, I think—I would not be surprised that we don’t see EURs over the 300,000 barrels that Matt indicated with a consistency with the laterals and the 20-stage fracs versus, say, a 12 to 15-stage frac. And we are evaluating in our area in Zavala—we’re just evaluating the industry activity up there. We think the EURs up there are going to be a little bit less, but we also think the drilling and completion costs, because it’s a little shallower, will be less also. So that particular acreage up there – and there’s about 10,000-something acres up there – that particular area up there is going to take a little bit of the valuation from industry and a couple of wells up there to determine the returns and economics for that particular acreage. So I think we are going to see differences throughout—not only throughout our acreage, but the industry will see throughout the trend differences in the Eagle Ford.

Robert Christensen – Buckingham Research Group

One final, if I may – when these things do go on pump, do you put them on electric submersible pumps or are they on pump jacks? What happens there at the end? Which is more cost effective, or how does it go?

Matt Reid

Well, we’ve done both. We’ve actually, early on to get a lot of the fluid from the frac off the formation, we’ve gone to submersible pumps or to gas lift. And then we eventually move toward a conventional rock pump as rates come down the 200, 300 barrel range.

Robert Christensen – Buckingham Research Group

Thank you very much.

Dan Dinges

Thanks, Robert.

Operator

Your next question comes from the line of Marshall Carver with Capital One South.

Marshall Carver – Capital One Southcoast

Yes, good morning. A couple of questions. On the production guidance for Q4 and also in the third quarter, looks like you had good gas production growth but tweaked down on oil. Why the tweak down on oil guidance?

Dan Dinges

Because we have—in order to handle our capital allocation, we had scheduled earlier more Petit wells to be drilled. But with the number of non-op Haynesville/Bossier wells, we have postponed some of the Petit drilling, which was oil related.

Marshall Carver – Capital One Southcoast

Okay. That makes sense. And then on the—both the Chainman Shale and the Heath play, could you mention how many acres—net acres you have in each of those plays, expected well costs, and if there are any well results around for each of those plays, please?

Dan Dinges

Yeah, I’ll let Phil Stalnaker, our VP of our North Region, answer that.

Phil Stalnaker

In the Chainman we have over—around 72,000 net acres, and that was a rank wildcat. Nothing else right around that particular area. In the Heath, we have over 100,000 net acres in that area. There are—it looks like there’s some recent activity but no results from the Heath in that area.

Marshall Carver – Capital One Southcoast

Okay, and the expected well costs?

Phil Stalnaker

On the Heath, we’re looking at, on this initial well, approximately $4 million completed.

Marshall Carver – Capital One Southcoast

And how much was the Chainman well?

Phil Stalnaker

The (inaudible) cost is a little over 2--$2.5 million.

Marshall Carver – Capital One Southcoast

Okay, that’s it for me. Thank you.

Dan Dinges

Thank you, Marshall.

Operator

Your next question comes from Jack Aydin with Keybanc.

Jack Aydin – Keybanc Capital Markets

Hey Dan.

Dan Dinges

Hey Jack. How are you?

Jack Aydin – Keybanc Capital Markets

Good. On the Lathrop—going back to Lathrop station. Your competitor got the permit. Was that single source—based on a single source or an aggregated source?

Dan Dinges

We understand it was based on a single source.

Jack Aydin – Keybanc Capital Markets

Okay, good. I’m glad that one. Now second, regarding the Haynesville, it’s basically looking a lot for JV or carry. How—what kind of progress you’re making in that area?

Dan Dinges

We have—we have a third party that’s helping us out with that. We have CAs that have been executed and we have a data room schedule set up, and we have a bid deadline set up also.

Jack Aydin – Keybanc Capital Markets

What is the deadline? The bid deadline?

Dan Dinges

December 15.

Jack Aydin – Keybanc Capital Markets

Okay.

Dan Dinges

The bid’s due December 15.

Jack Aydin – Keybanc Capital Markets

Third question – looking at your guidance, it looks like the exploration expenses guidance for the fourth quarter, it looks on the high. What did you bake into those numbers?

Dan Dinges

Let me get—let me get what that is. Okay, we had—we had 7 million in the Buckhorn seismic in that.

Jack Aydin- Keybanc Capital Markets

Okay. Thanks a lot.

Dan Dinges

Thank you, Jack.

Operator

And your final question comes from the line of Michael Hall with Wells Fargo.

Michael Hall – Wells Fargo Securities

Hey, thanks for the follow-up. Just quickly wanted to—you threw out, I think, 7.5 to 8.5 million per well in the Eagle Ford there. It’s a bit higher maybe than I had been thinking. What—can you break that out between, I guess, what the completion cost is versus the drilling cost?

Dan Dinges

Yeah, we have probably about 3 million or so in the drilling and 4.5 or so, or a little bit more, in the completion, depending on the number of stages.

Michael Hall – Wells Fargo Securities

Okay. And then one more, if I may – just coming back to the (inaudible) program for 2011 and how it interacts with the Lathrop air quality permit. You know, in the worst case if you don’t get it, why not spend less? It sounds like you’ll kind of spend the money no matter what. I was just trying to kind of understand that, given the big backlog.

Dan Dinges

Well yeah, that’s a fair question, Michael. We fully anticipate, again, getting the permit and we’re moving ahead because our expectation, if you put it on a risk basis and chance of success basis, we fully expect to get the permit. The type of permit that we’re requesting is not a unique permit for the oil and gas industry. It is just purely a clean, simple compressor station. Compression—in any shale play area that has gas, compression is going to be needed, so approval of this type of facility is going to be done if they want production. It’s just that easy. So if in fact we find that the Pennsylvania DEP has made decisions that they don’t want compression up there, I think you’re going to make see industry make a wholesale change, and not spend as much capital up there would be one of them.

Michael Hall – Wells Fargo Securities

Okay. That’s very helpful, thank you. And then I guess one last one – there was some discussion or some headlines yesterday that there may be a moratorium on the Pennsylvania state forest leasing. Would that at all impact your leasing plans for next year?

Dan Dinges

No. No, it will not.

Michael Hall – Wells Fargo Securities

Great. Thank you very much.

Dan Dinges

Thank you, Michael.

Operator

And you have a follow-up question from Robert Christensen with Buckingham Research.

Robert Christensen – Buckingham Research Group

Yes, thank you. On hedging in 2011, it appears to us that you did not add additional hedges in 2011. Is it the inability to hedge more, the unwillingness to hedge more, or even a view that gas prices get better and no reason to position more gas forward? Could you help us on the hedging story at Cabot, please?

Dan Dinges

Yeah, Robert, we did hedge an oil contract recently, so we did add a hedge there. As far as gas hedges, we wish we were 100% hedged at where we’re hedged right now in 2010, but we’re not. We do think that as far as where the strip price is right now, hedging at this level, we think, would be purely a defensive hedge, and you could make the argument both ways that I’ll go ahead and make that defensive hedge, but we think we’ll have price realizations at least where the strip price is today.

Robert Christensen – Buckingham Research Group

But with your cost structure, that would not appear to be running at profitable levels where strip prices are today; or barely, I guess, on 2011. With the cost structure all in, it’s like 392, (inaudible) BTU.

Dan Dinges

Well, if you look at the curve hits and the economics that we’re running—for example, where we’re allocating two-thirds of our capital in the Marcellus, we’re using a current EUR of 5.5 Bcfe. We have our current—we have our current IPs that we’re seeing up there, and using your number, Robert, and using our current existing completion cost, at $4.00 we are pushing 100% return, so we think that is a very good return for our shareholders.

Robert Christensen – Buckingham Research Group

Got it. So on everything that’s incremental in the Company, great returns. Historic doesn’t play under the sort of forward deck. Is that how to interpret that? I guess—

Dan Dinges

I’m not understanding your question.

Robert Christensen – Buckingham Research Group

Well to me, on a go-forward basis as you define the Marcellus, highly economic at $4.00, or 100% returns. Everything else, you know, your cost basis in the entire company, looking at your per unit costs, looking—all in, taxes, DD&A, G&A, what have you, was $3.92 in the quarter per Mcf. So the economics aren’t there sort of for the historical assets, but on everything that’s involved with growth, Marcellus and Eagle Ford, fantastic returns.

Dan Dinges

Yeah, and that kind of goes back to the statement I first made. I wish we were 100% hedged at our current strip price—I mean, our current hedge price.

Robert Christensen – Buckingham Research Group

Thank you very much.

Dan Dinges

Thank you.

Operator

There are no further questions at this time. I now hand the program back over to management for any further comments or closing remarks.

Dan Dinges

Well that’s it, Christy. I appreciate everybody’s interest and we do look forward to not only our ongoing program for 2010 but rolling into 2011; and I think you can see with some of the numbers that we put out today that we are yielding very positive returns for the shareholder with every dollar spent. I appreciate your interest and consideration. Thank you.

Operator

This concludes today’s conference call. You may now disconnect.

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